1. Technical Field of the Invention
The present invention generally relates to the purification of light hydrocarbon gas streams by removal of hydrogen sulfide (H2S) contaminant. More particularly the invention relates to methods that employ the catalytic partial oxidation of H2S to form elemental sulfur and water, and to catalyst compositions that are active for catalyzing such conversion. Still more particularly, the invention pertains to such catalysts and methods which favor the partial oxidation of the H2S component over partial oxidation of the hydrocarbon component of a H2S-containing light hydrocarbon gas stream.
2. Description of the Related Art
Hydrocarbon gases that occur as natural formations in the ground (“natural gas”) typically contain a mixture of light alkanes, chiefly methane and some C2-C4 alkanes, and often include a significant amount of hydrogen sulfide (H2S). Natural gas reserves containing more than 1% by volume (vol. %) H2S are common, and many naturally occurring formations have a much greater H2S content. Stranded natural gas reserves in the Middle East and in Canada, for example, typically have H2S concentrations in the range of 10-40 vol. %. The presence of H2S in natural gas is problematic. Not only does it have an intensely unpleasant odor, even when present at low concentrations, it is also toxic and often forms undesirable sulfur compounds as end products produced from the natural gas. Governmental regulations restrict the amount of H2S that can be introduced into the environment to only a few parts per million. Because it is more economical to transport some natural gas products in the form of a liquid rather than as a gas, most natural gas production operations include converting the natural gas to liquefied petroleum gas (LPG) at the well site. A drawback of working with the H2S-contaminated LPG is that, in concentrated form, the H2S is extremely corrosive to the steel pipes and containers used to transport the H2S-containing gases and liquids. As a result of those drawbacks, combined with the difficulty and expense of removing H2S from natural gas, the existing H2S-containing natural gas formations have tended to be underutilized in the petroleum industry.
Today there is great interest in utilizing the world's plentiful natural gas resources, and much effort in the petroleum industry is now being directed toward selectively removing the H2S component prior to using the natural gas. While various methods exist for removing hydrogen sulfide from gases and liquids during natural gas processing, most of those processes require large, expensive sulfur removal and sulfur recovery plants, also referred to as Claus plants or modified Claus plants, for processing the sulfur.
The Claus process alone is not suitable for cleaning up light hydrocarbon streams that contain H2S. Not only is the hydrocarbon content lost in the initial thermal combustion step of the Claus process, but carbon, carbonyl sulfide and carbon disulfide products cause catalyst fouling and dark sulfur. To avoid these problems, the usual way that H2S is removed from gaseous hydrocarbon streams generally involves an initial amine extraction process. In conventional industrial practice, a light hydrocarbon-containing gas stream that contains H2S is contacted with an alkanolamine solution. Alkanolamines commonly employed in the industry are monoethanolamine (MEA), diethanolamine (DEA), methyldiethanol amine (MDEA), diglycolamine (DGA), and diisopropanolamine (DIPA). These are basic nitrogen compounds. The basic alkanolamine reacts with the H2S and other gases that form acids when dissolved in water to form alkanolamine salts.
The hydrocarbon gas, substantially freed of H2S, is recovered and may be used as fuel or routed to another system for processing. After absorbing the H2S from the gas, the alkanolamine solution is transported, heated, and placed in a stripping tower. Steam, generated from boiling the alkanolamine solution at the bottom of the stripping tower, lowers the vapor pressure of the acid gas above the solution reversing the equilibrium of the acid gas/alkanolamine reaction shown above. The acid gases leaving the stripper are cooled to condense most of the remaining steam. The acid gas stream then goes to a conventional sulfur recovery plant, also referred to as a Claus plant or modified Claus plant. In the Claus plant, the H2S gas from the alkanolamine stripper is contacted with air or a mixture of oxygen and air in a flame. One third (⅓) of the H2S is burned according to the reaction:H2S+3/2O2→SO2+H2O  (I)The remaining ⅔ of the H2S is converted to sulfur via the Claus reaction:2H2S+SO23/xSx+2H2O  (II)(x=2, 6, or 8 depending on temperature and pressure)
The gases are cooled in a fire tube boiler after the burner. Nominally, this step converts 55 to 70% of the H2S to elemental sulfur. The equilibrium of the Claus reaction of (Reaction II) limits the conversion. To improve the yield, elemental sulfur is condensed from the gas stream. After sulfur condensation and separation from the liquid sulfur, the unreacted gases are heated to the desired temperature, passed over a catalyst that promotes the Claus reaction, and cooled again to condense and separate the sulfur. Typically, 2 to 3 stages of Claus reheater, reactor, and condenser stages are employed. Anywhere from 90 to 98% of the H2S fed to the unit is recovered as elemental sulfur. A Claus process is efficient for processing large quantities of gases containing a high concentration of H2S (i.e., >20% by volume) in plants producing more than 7000 metric tons of sulfur per year.
In the effluent from Claus plants, any remaining H2S, SO2, other sulfur compounds and elemental sulfur are either incinerated to SO2 and discharged to the atmosphere or absorbed by chemical reaction, or converted by hydrogen to H2S and recycled or absorbed by an alkanolamine solution. This is accomplished by various “tail gas” treatment units, which improve the efficiency of sulfur removal from the gas discharged to the atmosphere. For example, R. H. Hass et al. (Hydrocarbon Processing May 1981:104-107) describe the BSR/Selectox™ process for conversion of residual sulfur in Claus tail gas or for pre-Claus treatment of a gas stream. K-T Li at al. (Ind. Eng. Chem. Res. 36:1480-1484 (1997)) describe the SuperClaus™ TGT system which uses vanadium antimonate catalysts to catalyze the selective oxidation of hydrogen sulfide to elemental sulfur.
Amine strippers and Claus plants in use today for purifying H2S-contaminated light hydrocarbon streams are normally operated at less than 2 atmospheres pressure. Because of this low pressure operation, the pipes and vessels have very large diameters for the flow compared to most refinery or gas plant processes. The low pressure operation forces the equipment to be designed for low pressure drop in order to have adequate capacity. Since Claus-type processes cannot provide a high level of H2S conversion and selectivity for elemental sulfur product without the use of multiple Claus reactor stages, when treating high H2S concentration streams, a typical modified Claus plant, also includes one or more tail gas treatment units. Therefore, the desulfurization plant can be quite large and may include a great deal of equipment.
In addition to the Claus tail gas treatments which employ the direct oxidation of H2S to elemental sulfur, other techniques have been described in the literature for selectively oxidizing H2S employing aqueous redox chemistry utilizing chelated iron salts or nitrite salts in an attempt to purifying hydrogen sulfide contaminated hydrogen or gaseous light hydrocarbon resources. According to such techniques, the H2S-contaminated hydrogen or hydrocarbon stream is typically contacted directly with the redox reagent such as chelated iron (III) ions. The iron (III) is reduced to iron (II) ion while the H2S is converted to elemental sulfur. The sulfur in solid form is separated from the solution. Those types of redox units are generally considered to be practical when the amount of sulfur to be removed from the stream is below 5 long tons per day.
U.S. Pat. No. 4,311,683 (Hass et al.) describes a process for the removal of H2S from a feed gas, and the production of sulfur therefrom, by oxidation with oxygen and/or SO2 at temperatures between 250° and 450° F., using a stable oxidation catalyst comprising an oxide and/or sulfide of vanadium on a non-alkaline porous refractory oxide. The partial pressure of free sulfur in the oxidation reactor is kept below that necessary for condensation. It is said that H2, CO and light hydrocarbons present in the feed gas are not oxidized.
U.S. Pat. No. 5,603,913 describes several oxide catalysts that have been suggested for catalyzing the direct partial oxidation of H2S to elemental sulfur and water. Because the direct partial oxidation is not a thermodynamically reversible reaction, such methods offer potentially higher levels of conversion than is practically obtainable with only thermal and Claus oxidation of H2S. Most direct oxidation methods are applicable to sour gas streams containing relatively small amounts of H2S and large amounts of hydrocarbons, but are not particularly well suited for handling the more concentrated acid gas streams from refineries and from many natural gas formations. For this reason direct oxidation methods have been generally limited to use as tail gas treatments only, and have not found general industrial applicability for first stage sulfur removal systems from gases containing large quantities of H2S.
The restriction to low H2S concentration gases is due, in part, to the increase in adiabatic heating of the catalyst bed that occurs at higher concentrations of H2S, i.e., above about 3 vol. %.
The limit of heat tolerance of the reaction vessel, which is typically made of steel, can be quickly reached when a high concentration of H2S is reacted. Also, the higher temperatures (above about 350° C.) cause an increase in the rate of reaction of SO2 formation. Additionally, the H2S concentration range is usually kept low because of the necessity for supplying excess O2 to overcome deactivation of most direct oxidation catalysts caused by water. As a practical matter, the need for a stoichiometric excess of O2 precludes using H2S concentrations above about 2 vol. %. S. W. Chun et al. (Applied Catalysis B: Environmental 16:235-243 (1998)) describe a TiO2/SiO2 particulate catalyst that is not deactivated by the water formed in the partial oxidation reaction at a reactant gas ratio of 0.5-4 O2:H2S. In that report the H2S conversion is carried out with a fixed bed catalyst at a temperature of 275° C. and at a gas hourly space velocity (GHSV) of 3000 hr−1.
P. D. Clark et al. (Catalysis Communications (2004) 5:743-747) describe the use of a short-contact-time partial oxidation reactor (SCTR) for production of H2 from the catalytic partial oxidation of H2S. That process utilizes a quartz tube reactor to produce hydrogen, sulfur and water as the predominant products at a set temperature of 400° C. and a contact time of 13 ms, wherein the conversion of H2S is 64.6%, H2 selectivity is 20.8%, and the amount of SO2 in the product is less than 0.5% of the input H2S. Increased temperatures are reported to promote more SO2 formation with the same H2S/O2 ratio in the feed. That process does not appear to contemplate treatment of a hydrocarbon-containing H2S gas stream.
U.S. Patent Application Publication No. 2003/194366 describes certain catalysts and process for oxidizing hydrogen sulfide to sulfur dioxide and sulfur. In general, a gas stream containing H2S and other oxidizable components is contacted with a mixed metal oxide oxidation catalyst at a temperature less than or equal to about 500° C. in the presence of a selected amount of oxygen to generate SO2, sulfur or both wherein less than about 25 mol % by volume of the oxidizable components other than H2S and other sulfur-containing compounds are oxidized by the oxygen. It is said that, generally, the more active the metal oxide catalyst, the lower the reaction temperature that should be used, with the caveat that the reaction temperature should be maintained sufficiently above the sulfur dew point to avoid detrimental levels of sulfur condensation in the reactor. The more preferred temperature range for operation is said to be between about 160° C. to about 250° C., dependent upon the sulfur dew point.
The existing light hydrocarbon purification processes and systems typically require pre-treatment of the hydrocarbon-containing stream or post-treatment catalytic stages and absorbent treatments in order to preserve the useful hydrocarbon components of a gas stream. A practical and commercially attractive process for cleaning up H2S-contaminated hydrocarbon streams, and at the same time recovering useful elemental sulfur, will find widespread application in a number of industrial situations. The petroleum industry would welcome a way to better utilize the world's abundant natural gas resources that are contaminated by H2S.